UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION
ISO NEW ENGLAND, Inc.
Docket No. ER11-2580-000
MOTION TO INTERVENE AND COMMENTS OF THE NEW ENGLAND STATES COMMITTEE ON ELECTRICITY

Pursuant to Rules 212 and 214 of the Rules of Practice and Procedure of the Federal Energy Regulatory Commission (“Commission”) and the Commission’s December 30, 2010 Notice of Filing and its January 11, 2011 Notice of Extension of Time to submit Interventions and Comments through January 25, 2011, the New England States Committee on Electricity (“NESCOE”) hereby submits this motion to intervene and comments in the above-captioned docket.1

In the comments that accompany this filing, NESCOE respectfully requests that the Commission direct ISO New England, Inc. to convene further stakeholder discussions on a limited number of issues and to submit any additional changes to its market rules that may arise out of those discussions in a future filing with the Commission.2

I. COMMUNICATIONS

The names, titles, and offices of the persons to whom correspondence in regard to this proceeding should be addressed are as follows:

Heather Hunt*
Executive Director
New England States Committee on Electricity
242 Whippoorwill Lane
Stratford, Connecticut 06614
203-380-1477
HeatherHunt@nescoe.com

Elizabeth A. Grisaru
Whiteman Osterman & Hanna, LLP
One Commerce Plaza
Suite 1900
Albany, New York 12260
518-487-7624
egrisaru@woh.com

* Person designated for service

II. MOTION TO INTERVENE

NESCOE is the Regional State Committee for the New England region. NESCOE is governed by a board of managers appointed by the Governors of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont and is funded through a regional tariff administered by ISO New England, Inc. (“ISO-NE”).3 NESCOE’s purpose is to represent the interests of the New England region by advancing policies that will provide electricity at the lowest possible price over the long term, consistent with maintaining reliable service and environmental quality. In advancing these interests, NESCOE is active in matters related to resource adequacy and system planning and expansion.

The resolution of issues relating to calculating tie benefits, which are inputs into the determination of the Installed Capacity Requirement (“ICR”), will have an impact on the operation of New England’s power system and markets. Based on the foregoing, NESCOE has a direct and substantial interest in this proceeding, which is not adequately represented by any other party, and which serves the public interest. NESCOE respectfully requests that it be permitted to intervene in this matter.

III. COMMENTS

In its order in this proceeding issued on February 12, 2010 (the “Order”), the Commission directed ISO-NE to review with its stakeholders the methodology it would use for calculating tie benefits in future third annual reconfiguration auctions (hereafter, “Third ARA”).4 The Commission further required ISO-NE to file any proposed changes to the methodology by the end of 2010, for application to the Third ARA for the 2012/2013 Capacity Commitment Period.5 The Order also indicated that ISO-NE should provide analyses of alternative proposals and assess reliability needs, estimated emergency events, and the cost implications of various options.6 On December 30, 2010, in response to the Order, ISO-NE submitted proposed tariff revisions resulting from the stakeholder review.7

NESCOE participated in those stakeholder deliberations and supports many of the proposals presented in ISO-NE’s December 30 filing. In particular, NESCOE supports the proposed mechanisms for allocating tie benefits to individual transmission lines or groups of lines. NESCOE believes ISO-NE presented well-considered and reasonable analysis in support of this mechanism, and NESCOE encourages the Commission to adopt it as presented.

At the same time, NESCOE questions four aspects of the tie benefits calculation methodology presented in ISO-NE’s filing. NESCOE believes that ISO-NE’s proposed method may not represent the optimum balance of reliability and cost considerations, and that further stakeholder discussion and analysis would provide valuable guidance to all parties on this issue, without compromising market expectations for future auction cycles.8 Thus, NESCOE respectfully requests that the Commission direct further stakeholder processes on the matters described below:

1. The use of “at criteria” assumptions for external Control Areas in calculating tie benefits for any future Third ARA.

2. The level and appropriateness of the cost analysis performed by ISO-NE as of the date of its filing.

3. The exclusion of transmission constraints in external Control Areas if such constraints would increase the value of tie benefits.

4. The exclusion of modeling of the Ontario and PJM Control Areas.

A. ISO-NE’s use of “at criteria” conditions for external Control Areas is overly conservative and does not adequately consider consumer cost implications. ISO-NE proposes to model external Control Areas using “at criteria” conditions for the Third ARA. In its December 30, 2010 filing, ISO-NE explains its perspective that relying on “at criteria” assumptions for modeling external Control Areas is a reasonable approach. ISO-NE’s rationales can be summarized as follows:

• Both system planner efforts and market forces will tend to erode surplus capacity to the level required by reliability criteria, between the time of the calculation of tie benefits for the Third ARA and the actual capacity commitment period.
• Reliance on an “as is” expectation of the capacity available for emergency assistance is inconsistent with real-time operations and transmission system limitations.

NESCOE does not support the use of “at criteria” assumptions for purposes of calculating tie benefits in this context. NESCOE understands ISO-NE’s institutional responsibility for system reliability. However, NESCOE is concerned that the solution offered in the ISO Filing conflates multiple levels of conservatism. For example, the probabilistic analyses underlying both the “as is” and “at criterion” approaches already assume certain forced outage rates; despite this fact, ISO-NE appears to rely on the possibility of a unit trip during the Capacity Commitment Period to justify its rejection of the “as is” methodology.9 Similarly, ISO-NE applies long-term planning assumptions about the market signals impacting generation availability to its analysis of the short term implications of existing surplus, with unrealistically conservative results. NESCOE submits that ISO-NE’s approach risks raising consumer costs unnecessarily.

Throughout the stakeholder process, NESCOE and other participants encouraged ISO-NE to consider alternative approaches that would satisfy reliability needs in a way that recognizes consumer cost implications.10 While NESCOE commends ISO-NE for its efforts over the past several months to provide information as requested in relation to alternatives, NESCOE believes that some additional deliberation could significantly improve the cost-effectiveness of the results.

To this end, NESCOE supported and continues to support an alternative methodology presented in the stakeholder process by National Grid (the “Alternative Proposal”), which reflects the actual conditions likely to exist for the relevant Capacity Commitment Period.11 The Alternative Proposal incorporates “as-is” assumptions for external Control Areas in calculating tie benefits for a future Third ARA and sets an upper operational tie benefit limit (“UOTBL”) of 2,320 MW.12 As ISO-NE acknowledges in its December filing, the National Grid Alternative Proposal had the support of a majority of the Participants Committee at the final vote of the year.13 NESCOE continues to believe that the Alternative Proposal is more realistic than the method now proposed by ISO-NE, resulting in a less conservative bias in the calculation of the ICR while responding adequately to ISO-NE’s reliability concerns.

The Alternative Proposal’s cap addresses ISO-NE’s concern about the possible erosion of surplus capacity in external Control Areas between the time when the tie benefits for the Third ARA are calculated and the Capacity Commitment Period, which ISO-NE estimates to be six to seven months.14 The cap is significantly less than what the probabilistic calculation of tie benefits for that period would likely be, and thus protects load from any foreseeable decline in available resources. In fact, in response to an inquiry from NESCOE, ISO-NE performed a preliminary probabilistic calculation of tie benefits using as-is conditions. ISO-NE reported the result was a tie benefit of 4,000 MW. This result supports a conclusion that the UOTBL of 2,320 MW is sufficiently protective because it is highly unlikely – and perhaps unreasonable to assume – that more than 1,680 MW (4,000MW – 2,320MW) of surplus capacity will fail or retire in the six months following the tie benefit calculation.

The Alternative Proposal cap also mitigates ISO-NE’s concern about overstating the availability of tie benefits for emergency assistance. This concern about over-reliance on tie benefits may well be legitimate when the assumed tie benefit level is 4,000 MW. NESCOE does not believe the concern is as well founded when the tie benefit level is capped at 2,320 MW. NESCOE respectfully suggests that the Alternative Proposal may reflect a superior resolution of the competing concerns for reliability and reasonable costs, in that it adequately meets reliability needs while avoiding imposing excessive costs on ratepayers.

NESCOE further suggests that ongoing efforts to improve the efficiency of interregional transactions may alleviate many of the concerns ISO-NE expresses with reliance on emergency relief from external Control Areas. In a recent white paper, ISO-NE and the New York Independent System Operator propose to solve the recognized problem of inefficient tie schedules between New York and New England by optimizing their transmission links in the same way they currently utilize their internal transmission.15 This approach would involve coordinating real-time energy dispatch across both Control Areas – in effect coming close to implementing a joint energy dispatch. NESCOE submits that changes in real-time tie utilization and communications capabilities may impact the availability of resources for emergency relief in ways that provide additional support for the use of less conservatively-biased assumptions in the Third ARA.

B. ISO-NE’s cost analysis is incomplete and did not receive stakeholder review.

In its February 12, 2010 Order, the Commission required ISO-NE to provide an analysis of tie benefits assumptions. To that end, ISO-NE filed with the Commission a cost analysis report on tie benefits conducted by the Brattle Group.16 According to ISONE, “the Brattle Group performed an economic analysis of differing levels of tie benefits in an attempt to identify possible cost impacts and any cost inflexion points, and by so doing address the concern expressed by the Commission that the ISO should provide an analysis of cost implications associated with tie benefits.”

NESCOE appreciates that ISO-NE has, pursuant to the Commission’s direction, begun the process of initiating a mechanism by which it and its stakeholders could analyze the cost implications of different tie benefits calculation methods. However, ISO-NE’s effort, given the applicable time constraints, did not meet the Commission’s purposes in directing ISO-NE to undertake this step.

First, ISO-NE did not produce the Brattle Report for stakeholder review during the tie benefit stakeholder process, and thus important opportunities for discussion and clarification were missed. As ISO-NE noted “[w]hile The Brattle Group report was not finalized until close to the end of the 2010 tie benefits stakeholder process, The Brattle Group shared drafts of the report with the ISO throughout the course of its development” (emphasis added).

ISO-NE distributed the Brattle Report to states and stakeholders essentially on the eve of the final tie benefit vote in December 2010. Accordingly, the analysis provided in the Brattle Report was not available to inform the states’ and stakeholders’ consideration of the issues presented. Conversely, the states’ and stakeholders’ perspective on the approach and determinations of the Brattle Report did not inform the Brattle Group’s cost analysis or the conclusions ISO-NE drew from it; the conclusions ISO-NE presents in its December filing have not been discussed with states or stakeholders or otherwise tested through the stakeholder process.

Second, as ISO-NE acknowledges, the Brattle Report does not provide a cost impact assessment of any specific alternative proposal.17 To remedy these deficiencies, NESCOE requests that the Commission direct ISO-NE to re-present the Brattle Report to stakeholders and to add cost-impact analysis of the Alternative Proposal to the assessment. The Commission should further require a subsequent filing and comment opportunity to explore the extent to which states and stakeholders agree with the Brattle Report analyses; what inferences are reasonable to be drawn from the results; and the role of such cost analysis in determining the region’s approach to calculating tie benefits for purposes of the Installed Capacity auctions. NESCOE believes that further stakeholder discussion will ultimately enhance the value of the Brattle Report to all participants in this proceeding, and to the Commission.

C. The exclusion of transmission constraints in external Control Areas if such constraints would increase the value of tie benefits is not realistic and requires further consideration by ISO-NE and stakeholders.

ISO-NE states that its proposed methodology excludes any transmission constraints in external Control Areas if such constraints would increase the value of tie benefits.18 ISO-NE’s decision to exclude these constraints produces a less realistic representation of actual conditions than would including them because excluding them decreases the apparent value of tie benefits.

During the stakeholder process, several participants recommended that if ISONE’s modeling included constraints that limit tie benefits, then transmission conditions that increase tie benefits should also be modeled. Symmetrical modeling would produce a more realistic representation of tie benefit values than ISO-NE’s asymmetrical approach. This issue warrants further consideration by ISO-NE and stakeholders.

D. ISO-NE and Stakeholders Should Review Modeling of Ontario and PJM in no more than Three Years.

ISO-NE states that it determined, “with general support of stakeholders” not to model the Ontario and PJM Control Areas.19 ISO-NE decided not to model Ontario and PJM because: (1) it would be very difficult to quantify the amount of emergency assistance those areas might provide; and (2) it would take significant effort. What ISONE referred to as “general support” may be accurately described as reluctant acceptance; during the stakeholder process, several participants argued strongly for this additional modeling and suggested that the issue should be revisited if conditions change or as modeling capabilities expand. NESCOE requests that the Commission direct ISO-NE to revisit this issue in a stakeholder process if conditions change, and in any case in no more than three years; and to report the conclusions of that process to the Commission.

Conclusion

NESCOE supports the adoption of ISO-NE’s methodology with respect to the upcoming auction period. At the same time, NESCOE respectfully urges the Commission to direct ISO-NE to (1) undertake the further stakeholder discussions suggested in these comments, and (2) submit any tariff modifications that result from those additional discussions to the Commission in a future filing.

Respectfully submitted,

/s/ Elizabeth A. Grisaru______
Elizabeth A. Grisaru
Whiteman Osterman & Hanna
One Commerce Plaza
Albany, New York 12260
Phone: (518) 487-7624
Mail to: egrisaru@woh.com